The present invention relates to methods and compositions for treating subterranean formations. More particularly, the present invention relates to surfactant-based fluid loss control agents for surfactant gels, and associated methods.
Viscosified treatment fluids may be used in a variety of subterranean treatments. Such treatments include, but are not limited to, drilling operations, stimulation treatments, and sand control treatments; As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid.
Drilling operations typically require the use of a drilling fluid. During drilling operations, a viscosified treatment fluid (e.g., a drilling fluid) passes down through the inside of the drill string, exits through the drill bit, and returns to the drilling rig through the annulus between the drill string and well bore. The circulating drilling fluid, among other things, lubricates the drill bit, transports drill cuttings to the surface, and balances the formation pressure exerted on the well bore. Drilling fluids typically require sufficient viscosity to suspend drill cuttings. Viscosified treatment fluids also may be used in, other operations to transport and remove formation particulates from the well bore or the near well bore region. In some instances, these formation particulates may be generated during the course of drilling, digging, blasting, dredging, tunneling, and the like in the subterranean formation.
One common production stimulation operation that employs a viscosified treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a viscosified treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. The fracturing fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates function, inter alia, to prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. Once at least one fracture is created and the proppant particulates are substantially in place, the viscosity of the fracturing fluid usually is reduced, and the fracturing fluid may be recovered from the formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In gravel-packing treatments, the viscosified treatment fluid suspends particulates (commonly referred to as “gravel particulates”) for delivery to a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a gravel pack to enhance sand control. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation particulates from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the production tubing. Once the gravel pack is substantially in place, the viscosity of the treatment fluid is often reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “frac pack” operations) to provide stimulated production and an annular gravel pack to reduce formation sand production. In some cases, the treatments are completed with a gravel pack screen assembly in place, and the fracturing treatment fluid being pumped through the annular space between the casing and screen. In such a situation, the fracturing treatment usually ends in a screen-out condition, creating an annular gravel pack between the screen and casing. This allows both the fracturing treatment and gravel pack to be placed in a single operation.
Maintaining sufficient viscosity in these fluids is important for a number of reasons. Viscosity is desirable in drilling operations since treatment fluids with higher viscosity can, among other things, transport solids, such as drill cuttings, more readily. Maintaining sufficient viscosity is important in fracturing treatments for particulate transport as well as to create or enhance fracture width. Particulate transport is also important in sand control treatments, such as gravel packing. Also, maintaining sufficient viscosity may be important to control and/or reduce leak-off into the formation. To provide the desired viscosity, polymeric gelling agents commonly are added to the treatment fluids. Examples of commonly used polymeric gelling agents include, but are not limited to, guar gums and derivatives thereof, cellulose derivatives, biopolymers, and the like. The use of polymeric gelling agents, however, may be problematic. For instance, these polymeric gelling agents may leave an undesirable residue in the subterranean formation after use. As a result, potentially costly remedial operations may be required to clean up the fracture face and proppant pack. Foamed treatment fluids and emulsion-based treatment fluids have been employed to minimize residual damage, but increased expense and complexity often result.
To combat these and other problems associated with polymeric gelling agents, some liquid surfactants have been used as gelling agents. Certain surfactants, when mixed with an aqueous fluid having a certain ionic strength, are capable of forming a viscous fluid that has certain elastic properties, one of which may be shear thinning. Surfactant molecules (or ions) at specific conditions may form micelles (e.g., worm-shaped micelles, rod-shaped micelles, etc.) in an aqueous fluid. Depending on, among other things, the surfactant concentration, and the ionic strength of the fluid, etc., these micelles may impart increased viscosity to the aqueous fluid, such that the fluid exhibits viscoelastic behavior due, at least in part, to the association of the surfactant molecules contained therein. As a result, these treatment fluids exhibiting viscoelastic behavior may be used in a variety of subterranean treatments where a viscosified treatment fluid may be useful. Such viscosified fluids may be referred to herein as “surfactant gels.” No particular structure or composition is implied by the term. Surfactant gels generally are thought to be nondamaging to the subterranean formation in which they are used because they do not leave an undesirable polymer residue.
Although such fluids may be used in downhole applications, oftentimes surfactant gels may experience significant fluid loss complications. This may be because they do not build a filter cake as a more traditional viscosified treatment fluid that comprises a polymeric gelling agent does. More fluid is lost as a result. This problem may be worse at higher temperatures. Moreover, adding a gelling agent polymer to the surfactant gel to combat this fluid loss problem is generally not desirable because it defeats the purpose of using a surfactant gel. Additionally, any formation fluids that may be present in the subterranean formation (e.g., hydrocarbons, additives, solvents, corrosion inhibitors, etc.) may reduce the viscosity of the surfactant gel, which increases fluid loss.
Conventional attempts to combat such fluid loss problems have not met with much success. One method is to do nothing, and just pump a significantly larger fluid volume at higher rates to combat the fluid loss. However, as known by those skilled in the art, this is not an optimal method for treating with surfactant gels. Another method includes pumping a pad or a pre-pad fluid that contains a polymeric gelling agent before or with the surfactant gel. This method, however, is undesirable because it defeats one of the purposes of using a surfactant gel, i.e., using a non-polymeric containing fluid. Another method is to foam the surfactant gel with a gas or with the use of an expanding additive. Such methods can be logistically difficult to manage, however, especially in off-shore or remote well locations. Moreover, the pumping rate at which the foamed fluid may be pumped is limited. Yet another method to combat fluid loss control in surfactant gels includes adding a fluid loss control agent. Common fluid loss control agents include silica, mica, and calcite, alone, in combination, or in combination with starch. Use of these fluid loss control additives alone in surfactant gels, however, has been observed to give only modest decreases in fluid loss. The poor performance of these conventional fluid loss additives is typically attributed to the period of high leak-off (spurt) before a filter cake is formed and the formation of a filter cake permeable to the surfactant gel. Additionally, the silica flour may remain in the formation, which is damaging to the formation, and therefore, undesirable. Polylactic acid fluid loss control agents generally have temperature limitations at the lower temperatures. Additionally, many traditional attempts to control fluid loss in surfactant gels are either not temporary or provide no gel stabilization.